The present invention relates to a tool for running tubulars into subterranean wellbores, and more specifically to an improved moving mechanism in the tool whereby the tool is operable for internally gripping a tubular member for torquing individual tubular joints or strings, rotating and/or reciprocating a tubular string which is additionally adapted for filling and circulating fluid in and through a tubular string and for cementing a tubular string within a wellbore.
Subterranean wells are drilled for many purposes, including the recovery of hydrocarbons, carbon dioxide, and removal of contaminants. Additionally, subterranean wells are drilled for the purpose of injecting substances back into subterranean formations, such as hydrocarbons into a salt dome, water into a reservoir, and disposal of hazardous material.
The process of drilling subterranean wells consists of drilling a hole in the earth down to a reservoir or formation in which a substance is intended to be removed from or injected. Hereinafter this disclosure will refer to the process in regards to drilling for recovery of hydrocarbons, although the tool of the present application is adapted for the use in any type of drilling operation.
Typically, in the drilling of wells, the well is drilled in sections. After each section of the well is drilled a casing string is placed within the wellbore. Casing is pipe which is placed in the wellbore to form a conduit from the subterranean reservoir to the surface. Casing also prevents the wellbore from collapsing and provides a barrier to the flow of fluids between formations which the wellbore penetrates. Once a string of casing is run into the hole, it is typically cemented in place. It is very common for a well to include more than one section of casing, each section having a different diameter from other sections of casing.
Casing is commonly run into the hole one joint or stand at a time. Each joint is picked up and then connect to the top most joint of the casing string which is typically supported at the rig floor by casing spider. Power tongs may then be used to threadedly connect the additional casing joint to the casing string in the hole. Once the joint or stand of casing has been connected to the casing string, a casing elevator which normally grips the outside diameter of the casing is lowered over the added joint or stand and activated so as to grip the casing string. The casing string is then lifted by the external casing elevator thus allowing the spider to release the casing string. Once the spider grip has released the casing string the string may be lowered into the wellbore.
As each additional joint or stand of casing is connected to the casing string, as set out above, it is filled with fluid for running into the hole. This fluid prevents floatation of the casing string, maintains pressure within the well to prevent formation fluid from coming back up the hole, and prevents the casing from collapsing. The filling of each joint or stand of casing as it is run into the hole is the fill-up process. Lowering the casing into the wellbore is typically facilitated by alternately engaging and disengaging elevator slips and spider slips with the casing string in a step wise fashion, facilitating the connection of an additional stand of casing to the top of the casing string as it is run into the hole. The prior art discloses hose assemblies, housings coupled to the uppermost portion of the casing, and tools suspended from the drill hook for filling the casing.
When casing is run into the hole it is sometimes necessary to circulate fluid. Circulating fluid requires pumping a fluid down the interior of the casing, out the bottom of the casing and back up the hole through the annulus between the casing and wellbore. Fluid is circulated through the well when casing gets stuck in the hole, to clean the hole, to condition the drilling fluid, to test the well and surface equipment, and to cement the casing within the wellbore.
Circulation of the fluid is sometimes necessary when resistance is encountered as the casing is lowered into the wellbore, preventing the running of the casing string into the hole. This resistance to running the casing into the hole may be due to such factors as drill cuttings, mud cake, caving of the wellbore, or a tight hole among other factors. In order to circulate the drilling fluid, the top portion of the casing must be sealed so that the interior of the casing may be pressurized with fluid. Since the casing is under pressure the integrity of the seal is critical to safe operation, and to minimize the loss of expensive drilling fluid. Once the obstruction is removed the casing may be run into the hole as before.
Often when casing is stuck in the hole, circulation of fluid alone is insufficient to free the casing. At these times it is necessary to rotate and reciprocate the casing to free it. Heretofore, it was necessary to rig down prior art fill-up and circulating tools to rig up tools to rotate and reciprocate the casing string. In these situations it was impractical to then be able to circulate fluid while the casing is being rotated and reciprocated. This process of rigging up and down is very time consuming, costly, and increases the risk of injury to rig personnel.
Once the casing string is run into the hole to a desired depth it is cemented within the hole. The purpose of cementing the casing is to seal the casing to the wellbore formation. In order to cement the casing within the wellbore it is common practice to remove the assembly which is used to fill and/or to circulate fluid from the drilling rig and a cementing head apparatus is installed atop the casing string. This process is time consuming, requires significant manpower, and subjects the rig crew to potential injury when handling and installing the additional equipment.
The prior art discloses separate devices and assemblies for (1) filling drilling fluid in and circulating fluid through tubular members or strings; (2) lowering, and torquing individual joints or strings of tubulars; (3) rotating and reciprocating tubulars members or strings; and (4) cementing operations. These prior art assemblies requiring re-rigging of equipment each time a new sequence in the running and setting of casing is changed. An internal elevator is disclosed in U.S. Pat. No. 4,320,915 assigned to Varco International, Inc. As disclosed, this prior art internal elevator does not disclose or provide a conduit through the elevator for filling the tubular member with a fluid or circulating fluids through the tubular string.
It would be a benefit therefore, to have an internal elevator adapted for internally gripping tubulars and allowing fluid to be pumped through the tool which may be used with top drive or rotary drilling rigs. It would be a further benefit to have an internal elevator which allows an operator to torque individual tubular joints or strings together or apart, rotate, and reciprocate tubular joints or strings. It would be a still further benefit to have an internal elevator which may used both-in filling tubulars with fluid and circulating fluid therethrough. It would be an additional benefit to have an internal elevator which may be used in conjunction with conventional fill-up and circulating tools, and cementing apparatus.
Accordingly, a tubular running tool adapted for use on a rotary or top drive drilling rig of the type for inserting and selectively, internally gripping a tubular which may be utilized to lift, lower, rotate, and torque tubulars, and which may be used to fill and or circulate fluid in and through tubulars and to cement tubulars within a wellbore is provided. The internal tubular running tool may be used as or in conjunction with fill-up and circulating tools and with cementing heads wiper plug assemblies among other tools. The tubular running tool includes: a barrel forming an axial fluid pathway therethrough, the barrel having a top end and a bottom end, the barrel forming a lower connecting section; at least one slip movably connected to the connecting section for selectively engaging an interior portion of a tubular member; and a moving mechanism functionally connected between the slips and the barrel for moving the slips in engaging contact with and from the tubular member. The tubular running tool may further include a sealing element for sealing the annulus between the tool and the interior surface of the tubular.
In a preferred embodiment, the barrel has a top end which is adapted for connecting equipment thereto such as top drive assemblies, push plate assemblies, various pups or subs, and cementing heads. The barrel may form an elevator section for connecting elevators thereto. The lower end is adapted for connecting tools such as fill-up and circulating tools, mud saver valves, and wiper plug assemblies among other tools and equipment.
The connecting section may be tapered, tapering outwardly toward the bottom end or the downhole portion of the barrel. The tapered section may be conical or substantially conical in form. In a preferred embodiment of the present invention the tapered section is faceted. The faceted portions of the tapered section may be substantially planar. The slips are movably connected to the tapered section. In a preferred embodiment, the slips are movably connected to each faceted and/or planar section which is formed. One mode of movably connecting the slips to the planar sections is via a retaining pin extending from an interior side of the slip and insertable into a slot formed by the faceted section. The slips are movable along the tapered section in a manner such that as the slips are moved towards the lower or broader end of the tapered section the slips are moved outwardly from the barrel and into engaging contact with the interior wall of the tubular in which the device is inserted. When the slips are moved towards the upper or narrower portion of the tapered section the slips are disengaged from gripping contact with the internal wall of the tubular.
The slips may be conventional type slips which are used in elevators and in spiders, however, the slips are inverted. These slips may have formed thereon ribs or gripping surfaces for gripping the tubular. In a preferred embodiment, the slips have removable gripping inserts, providing the ability to easily replace the gripping portion of the slips as they wear through use.
A moving mechanism is connected between the slip(s) and the barrel to facilitate the movement of the slips along the connecting section into and out of gripping contact with the tubular. This mechanism may be a pneumatic or hydraulic cylinder including a piston or rod, or other well known moving assemblies. In one preferred embodiment, the moving mechanism is a pneumatic cylinder because of its reliability and the available source of pressurized air on the drilling rig. The improved moving mechanism of the present invention comprises a tubular cylinder housing mounted in encircling relationship to the barrel and a cylindrical rod moveable within the tubular cylinder housing. A piston is mounted within the tubular cylinder housing is secured to the cylinder rod. The piston is preferably in encircling relationship to the barrel member. The tubular cylinder housing may further comprise an inner cylindrical element and an outer cylindrical element with the cylinder rod being moveable therebetween.
The moving mechanism may be directly connected to the slips or may be connected to the slips via arms which facilitate the movement of the slips along the connecting section. Additionally, a single moving mechanism may be functionally connected to more than one slip via means such as a sleeve or ring in connection between the moving mechanism and the slips. One such embodiment includes a sleeve movably connected about the barrel, the sleeve functionally connected between the moving mechanism and the slips such that as the moving mechanism is operated the sleeve moves along a portion of the barrel thereby moving the slips along the length of the connecting section.
Another intended and preferred embodiment includes an upper and lower sleeve movably connected or disposed about the barrel. The moving mechanism, or cylinder and rod in this example is connected to both the upper and lower sleeve. The cylinder is further functionally connected directly to, or via the lower sleeve and preferably movable arms to the slips. In this manner, when it is desired to internally grip the tubular the moving mechanism is activated, the upper sleeve is then moved toward the upper end of the barrel and the lower sleeve toward the connecting section thereby moving the slips downwardly and outwardly along the connecting section thereby engaging and gripping the interior of the tubular. This movement of the slips, via the upper and lower sleeve, provides a visual means for the operator to determine when the slips are in a position gripping the interior of the tubular. When desired to disengage the tool from contact with the tubular, the moving mechanism is again activated moving the upper sleeve and lower sleeve toward one another thereby moving the slips upward along the connecting section and out of contact with the interior of the tubular.
The internal gripping, tubular running tool may additionally be used as a fishing tool. In this embodiment, the tool in its most rudimentary embodiment may be run into the hole to stab into a string or joint of pipe which is lost in the hole. The moving mechanism is then activated so as to move the slips into engagement with the interior wall of the dropped string or joint Once engagement is accomplished the lost string or joint can be raised to the surface for removal, and the tubular running operation continued.
The tubular running tool may be used as a fill-up and circulating tool or in combination with a fill-up and circulating tool. When used as a fill-up and circulating tool the tubular running tool may include a sealing element attached to the barrel. The sealing element may be an inflatable packer, a flexible cup, or any other device which will seal against the tubular in which inserted, substantially preventing fluid to flow from below the sealing element through the annulus formed between the tool and the tubular and above the sealing element. In this configuration, the tubular running tool may further include equipment such as a mud saver valve, a guide ring, guide nose, and/or a nozzle connected to the lower end of the tubular running tool.
The tubular running tool may be used in combination with a fill-up and circulating tool. One such tool is described in U.S. Pat. No. 5,735,348, although the tubular running tool of the present invention may be used with all known fill-up and circulating tools. The fill-up and circulating tool may be connected to the upper or lower end of the tubular running tool, although it is preferred to run the fill-up and circulating tool connected to the lower end of the tubular running tool.
When the casing is run to the desired depth and drilling fluid filling and circulation is no longer required, the assembly may be configured for the cementing process. The drilling fluid lines are disconnected and replaced with the cement pump lines. After the drilling fluid flow is stopped, the apparatus is withdrawn from the casing to expose the lower end of the tubular running tool or the connected fill-up and circulating tool. The mud saver valve and hose extension assembly may be simply uncoupled from the lower body of the apparatus and a cementing wiper plug assembly connected to the lower end of the tubular running tool or to the fill-up and circulating tool connected to the tubular running tool. Additionally, a cementing head or cementing plug container is connected to the top end of the apparatus. The apparatus with the cement plug assembly and cement pump lines installed is then lowered back into the casing. Once the sealing device is engaged with the casings the cementing process begins. The plug release mechanism may be initiated at the appropriate times during the cementing process to release the cement wiper plugs.